nisource Statistical Summary Book 2004

The NiSource Portfolio

page 1

NiSource Inc.
NiSource Inc. (NiSource) is an energy holding company whose subsidiaries provide natural gas, electricity and
other products and services to approximately 3.7 million customers located within a corridor that runs from the
Gulf Coast through the Midwest to New England. NiSource’s primary business segments are: Gas Distribution
Operations; Gas Transmission and Storage Operations; Electric Operations; and Other Operations.
Gas Distribution Operations
NiSource’s natural gas distribution operations serve more than 3.3 million customers in 9 states and operate over
56,000 miles of pipeline. Through its wholly owned subsidiary, Columbia, NiSource owns five distribution subsidiaries
that provide natural gas to approximately 2.2 million residential, commercial and industrial customers in Ohio,
Pennsylvania, Virginia, Kentucky and Maryland. NiSource also distributes natural gas to approximately 784,000
customers in northern Indiana through three subsidiaries: Northern Indiana Public Service Company (Northern
Indiana), Kokomo Gas and Fuel Company and Northern Indiana Fuel and Light Company, Inc. Additionally, NiSource’s
subsidiaries Bay State and Northern Utilities, Inc. distribute natural gas to more than 335,000 customers in
Massachusetts, Maine and New Hampshire.
Gas Transmission and Storage Operations
NiSource’s Gas Transmission and Storage Operations subsidiaries own and operate approximately 16,000 miles of
interstate pipelines and operate one of the nation’s largest underground natural gas storage systems capable of storing
approximately 646 billion cubic feet (Bcf) of natural gas. Through its subsidiaries, Columbia Gas Transmission
Corporation (Columbia Transmission), Columbia Gulf Transmission Company (Columbia Gulf), Crossroads Pipeline
Company and Granite State Gas Transmission, Inc. (Granite State), NiSource owns and operates an interstate pipeline
network extending from offshore in the Gulf of Mexico to near Lake Erie, New York and the eastern seaboard. Together,
these companies serve customers in 19 northeastern, mid-Atlantic, midwestern and southern states and the District of
Columbia. The Gas Transmission and Storage Operations subsidiaries are engaged in several projects that will expand
their facilities and throughput. The largest such project is the proposed Millennium Pipeline. The Millennium Pipeline is
a project proposed by a partnership of energy companies including Columbia Transmission, which would replace parts
of an existing Columbia Transmission pipeline. Another project is Hardy Storage, a Columbia Transmission partnership
to develop a storage field in West Virginia to provide additional natural gas storage for the eastern United States.
Electric Operations
NiSource generates and distributes electricity through its subsidiary Northern Indiana to approximately 446,000 customers
in 21 counties in the northern part of Indiana. Northern Indiana owns and has the ability to operate four coal-fired electric
generating stations with a net capability of 3,059 megawatts (mw), six gas-fired generating units with a net capability of
323 mw and two hydroelectric generating plants with a net capability of 10 mw. These facilities provide for a total system
net capability of 3,392 mw.
Other Operations
The Other Operations segment participates in energy-related services including gas marketing, power trading and
ventures focused on distributed power generation technologies, including a cogeneration facility, fuel cells and storage
systems. NiSource subsidiary PEI Holdings, Inc., operates the Whiting Clean Energy project, which is a 525 mw
cogeneration facility that uses natural gas to produce electricity for sale in the wholesale markets and also provides
steam for industrial use.

Business Segments Primary Subsidiaries
% of 2004 Operating Income
• Bay State Gas Co.
• Columbia Gas of Kentucky
• Columbia Gas of Maryland
• Columbia Gas of Ohio
• Columbia Gas of Pennsylvania
• Columbia Gas of Virginia
• Columbia Gas Transmission
• Columbia Gulf Transmission
• Crossroads Pipeline
• Granite State Gas Transmission
• Kokomo Gas and Fuel Co.
• Northern Indiana Fuel & Light Co.
• Northern Indiana Public Service Co.
• Northern Utilities
• Whiting Clean Energy

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Contents
FINANCIAL

Consolidated Financial Data and Ratios .......................................................................................................4
Statements of Consolidated Income .............................................................................................................5
Consolidated Balance Sheets ........................................................................................................................6
Statements of Consolidated Cash Flows ......................................................................................................8
Statements of Consolidated Capitalization ..................................................................................................9
Statements of Consolidated Long-Term Debt ............................................................................................10
Income Taxes ..................................................................................................................................................11
Statements of Consolidated Common Stockholders’ Equity and Comprehensive Income................12
Current Security and Bond Ratings .............................................................................................................14

STOCKHOLDERS

Common Stockholders — State...................................................................................................................15
Common Stockholders...................................................................................................................................15

BUSINESS SEGMENTS

Gas Distribution Statistics.............................................................................................................................16
Gas Distribution Customers and Throughput Statistics by State .......................................................17
Gas Transmission and Storage Operations................................................................................................18
Electric Operations.........................................................................................................................................19
Electric Generation and Production Statistics ......................................................................................20
Fuel for Electric Generation ......................................................................................................................21
Capacity and Operating Margins .............................................................................................................22

Glossary of Selected Energy Terms.............................................................................................................23
Board of Directors and NiSource Ofﬁcers.................................................................................................24
Shareholder Information/Contacts ..............................................................................................back cover

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Consolidated Financial Data and Ratios
Year Ended December 31, (in millions, except per share amounts) 2004 2003 2002 2001 2000

Return on average common equity 9.5% 2.0% 9.7% 6.3% 6.3%
Times interest earned (pre-tax) 2.54 2.30 2.04 1.47 1.69
Dividends paid per share 0.92 1.10 1.16 1.16 1.08
Dividend payout ratio 55.8% 333.3% 65.5% 110.5% 96.4%
Market values during the year:
High 22.82 21.97 24.99 32.55 31.50
Low 19.65 16.39 14.51 18.25 12.81
Close 22.78 21.94 20.00 23.06 30.75
Book value of common stock 17.69 16.81 16.78 16.72 16.59
Market-to-book ratio at year end 128.8% 130.5% 119.2% 137.9% 185.4%
Total Assets 16,988.0 16,624.2 17,942.6 18,826.6 20,570.5
Capital Expenditures 517.0 574.6 531.9 525.3 331.1
Capitalization
Common stockholders’ equity 4,787.1 4,415.9 4,174.9 3,469.4 3,409.1
Preferred and preference stock 81.1 81.1 84.9 88.6 132.7
Company-obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely Company debentures — — 345.0 345.0 345.0
Long-term debt 4,835.9 5,993.4 4,849.5 6,065.1 5,802.7
Total Capitalization 9,704.1 10,490.4 9,454.3 9,968.1 9,689.5
Number of employees 8,628 8,614 9,307 12,501 14,674
Operating Income (Loss)
Gas Distribution Operations $ 440.3 $ 506.4 $ 459.1 $ 380.8 $ 241.0
Gas Transmission and Storage Operations 363.1 398.8 398.3 349.0 45.7
Electric Operations 306.2 267.5 322.3 340.7 353.0
Other Operations (32.3) (43.8) (43.1) (69.6) 55.4
Corporate (5.3) (12.6) 15.6 (33.0) (113.3)
Consolidated $ 1,072.0 $ 1,116.3 $ 1,152.2 $ 967.9 $ 581.8
Depreciation and Amortization
Other Operations 13.3 11.2 10.3 8.7 22.4
Corporate 9.5 9.1 10.1 11.0 4.5
Consolidated $ 509.7 $ 497.0 $ 491.2 $ 576.7 $ 364.1
Assets
Gas Distribution Operations $ 6,332.2 $ 6,096.4 $ 5,967.0 $ 5,889.0 $ 6,224.8
Gas Transmission and Storage Operations 3,053.3 2,920.4 2,940.1 2,990.5 3,094.2
Electric Operations 3,114.2 3,079.7 2,968.8 3,102.0 3,522.2
Other Operations 1,467.9 1,412.5 1,727.1 1,579.6 2,695.1
Corporate 3,020.4 3,115.2 4,339.6 5,265.5 5,034.2
Consolidated $16,988.0 $16,624.2 $17,942.6 $18,826.6 $20,570.5
Capital Expenditures
Other Operations (8.2) 19.3 5.3 46.1 36.3
Corporate 8.6 11.0 4.4 — —
Consolidated $ 517.0 $ 574.6 $ 531.9 $ 525.3 $ 331.1

The results in the table above for 2000 are not comparable as a result of the acquisition of Columbia Energy Group on November 1, 2000. Also, in 2002, NiSource Inc. discontinued the
amortization of goodwill consistent with SFAS No. 142, “Goodwill and Other Intangible Assets”.

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Statements of Consolidated Income
Year Ended December 31, (in millions, except per share amounts) 2004 2003 2002
Net Revenues
Gas Distribution $3,801.8 $3,554.5 $2,890.4
Gas Transportation and Storage 1,013.4 1,033.5 1,014.1
Electric 1,121.0 1,115.9 1,103.6
Other 730.0 542.7 311.7
Gross Revenues 6,666.2 6,246.6 5,319.8
Cost of Sales 3,610.5 3,186.3 2,248.9
Total Net Revenues 3,055.7 3,060.3 3,070.9

Operating Expenses
Operation and maintenance 1,211.7 1,185.9 1,185.0
Depreciation and amortization 509.7 497.0 491.2
(Gain) on sale or impairment of assets (3.1) (24.9) (27.5)
Other taxes 265.4 286.0 270.0
Total Operating Expenses 1,983.7 1,944.0 1,918.7
Operating Income 1,072.0 1,116.3 1,152.2

Other Income (Deductions)
Interest expense, net (403.9) (464.7) (516.4)
Minority interests — (2.5) (20.4)
Preferred stock dividends of subsidiaries (4.4) (4.5) (6.7)
Other, net 7.4 15.3 8.3
Total Other Income (Deductions) (400.9) (456.4) (535.2)
Income From Continuing Operations Before Income Taxes
and Change in Accounting 671.1 659.9 617.0
Income Taxes 240.9 234.2 218.9
Income From Continuing Operations Before Change in Accounting 430.2 425.7 398.1
Income (Loss) from Discontinued Operations — net of taxes 6.1 (0.5) 18.2
Loss on Disposition of Discontinued Operations — net of taxes — (331.2) (43.8)
Change in Accounting — net of taxes — (8.8) —
Net Income $ 436.3 $ 85.2 $ 372.5

Basic Earnings (Loss) Per Share ($)
Continuing operations $ 1.63 $ 1.64 $ 1.89
Discontinued operations 0.02 (1.28) (0.12)
Change in accounting — (0.03) —
Basic Earnings Per Share $ 1.65 $ 0.33 $ 1.77

Diluted Earnings (Loss) Per Share ($)
Continuing operations $ 1.62 $ 1.63 $ 1.87
Discontinued operations 0.02 (1.27) (0.12)
Change in accounting — (0.03) —
Diluted Earnings Per Share $ 1.64 $ 0.33 $ 1.75

Dividends Declared Per Common Share $ 0.92 $ 1.10 $ 1.16
Basic Average Common Shares Outstanding (millions) 263.7 259.6 211.0
Diluted Average Common Shares (millions) 265.5 261.6 212.8

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Consolidated Balance Sheets
As of December 31, (in millions) 2004 2003 2002

ASSETS
Property, Plant and Equipment
Utility Plant $16,194.1 $15,977.3 $15,579.7
Accumulated depreciation and amortization (7,247.6) (7,095.9) (6,813.7)
Net utility plant 8,946.5 8,881.4 8,766.0
Other property, at cost, less
accumulated depreciation 438.2 409.3 415.3
Net Property, Plant and Equipment 9,384.7 9,290.7 9,181.3
Investments and Other Assets
Assets of discontinued operations
and assets held for sale 23.4 20.7 1,571.0
Unconsolidated afﬁliates 108.1 113.2 125.1
Other investments 72.5 74.7 51.6
Total Investments 204.0 208.6 1,747.7
Current Assets
Cash and cash equivalents 30.1 27.3 31.1
Restricted cash 56.3 22.8 24.2
Accounts receivable, net 536.7 546.3 545.5
Unbilled revenue, net 352.7 268.0 305.2
Gas inventory 452.9 429.4 255.3
Underrecovered gas and fuel costs 293.8 203.2 206.1
Materials and supplies, at average cost 70.8 71.5 68.6
Electric production fuel, at average cost 29.2 29.0 39.0
Price risk management assets 61.1 74.3 66.4
Exchange gas receivable 169.6 174.8 120.1
Regulatory assets 136.2 114.5 99.5
Prepayments and other 96.2 101.8 111.8
Total Current Assets 2,285.6 2,062.9 1,872.8
Other Assets
Price risk management assets 148.3 114.4 115.1
Regulatory assets 568.4 575.5 608.8
Goodwill 3,687.2 3,687.2 3,722.1
Intangible assets 520.3 527.1 552.2
Deferred charges and other 189.5 157.8 142.6
Total Other Assets 5,113.7 5,062.0 5,140.8
Total Assets $16,988.0 $16,624.2 $17,942.6

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Consolidated Balance Sheets

CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity
Common stock — $0.01 par value, 400,000,000 shares authorized;
270,625,370; 262,630,409; and 248,860,178 shares issued and outstanding, respectively $ 2.7 $ 2.6 $ 2.5
Additional paid-in-capital, net of deferred stock compensation 3,924.0 3,752.2 3,388.9
Retained earnings 925.4 731.3 930.9
Accumulated other comprehensive loss and other common stock equity (65.0) (70.2) (147.4)
Total Common Stock Equity 4,787.1 4,415.9 4,174.9
Preferred Stocks —
Series without mandatory redemption provisions 81.1 81.1 81.1
Series with mandatory redemption provisions — — 3.8
Company-obligated mandatorily redeemable preferred securities
of subsidiary trust holding solely Company debentures — — 345.0
Long-term debt, excluding amounts due within one year 4,835.9 5,993.4 4,849.5
Total Capitalization 9,704.1 10,490.4 9,454.3
Current Liabilities
Current portion of long-term debt 1,299.9 118.3 1,224.9
Short-term borrowings 307.6 685.5 913.1
Accounts payable 648.4 496.6 536.7
Dividends declared on common and preferred stocks 1.1 1.8 1.1
Customer deposits 87.1 80.4 65.2
Taxes accrued 160.9 210.8 222.8
Interest accrued 84.1 82.4 76.6
Overrecovered gas and fuel costs 15.5 29.2 13.1
Price risk management liabilities 46.9 36.5 39.7
Exchange gas payable 325.1 290.8 411.9
Current deferred revenue 31.5 28.2 17.5
Regulatory liabilities 30.2 73.7 13.5
Accrued liability for postretirement and postemployment beneﬁts 85.5 64.3 48.9
Other accruals 478.4 418.0 391.8
Total Current Liabilities 3,602.2 2,616.5 3,976.8
Other Liabilities and Deferred Credits
Price risk management liabilities 5.5 0.2 3.2
Deferred income taxes 1,665.9 1,589.2 1,517.8
Deferred investment tax credits 78.4 87.3 96.3
Deferred credits 58.0 72.7 100.9
Noncurrent deferred revenue 87.4 113.0 130.1
Accrued liability for postretirement and postemployment beneﬁts 413.0 406.9 419.2
Preferred stock liabilities with mandatory redemption provisions 0.6 2.4 —
Liabilities of discontinued operations and liabilities held for sale — — 959.9
Regulatory liabilities 1,168.6 1,061.6 1,073.2
Other noncurrent liabilities 204.3 184.0 210.9
Total Other Liabilities and Deferred Credits 3,681.7 3,517.3 4,511.5
Commitments and Contingencies — — —
Total Capitalization and Liabilities $16,988.0 $16,624.2 $17,942.6

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Statements of Consolidated Cash Flows
Year Ended December 31, (in millions) 2004 2003 2002

Operating Activities
Net Income $ 436.3 $ 85.2 $ 372.5
Adjustments to reconcile net income to net cash from continuing operations:
Depreciation and amortization 509.7 497.0 491.2
Net changes in price risk management assets and liabilities 16.3 (4.3) (43.3)
Deferred income taxes and investment tax credits 97.5 77.9 95.8
Deferred revenue (22.3) (6.4) (15.2)
Stock compensation expense 8.0 12.9 7.3
Gain on sale or impairment of assets (3.1) (24.9) (27.5)
Change in accounting, net of tax — 8.8 —
Loss (Income) from unconsolidated afﬁliates (0.9) 5.4 (2.6)
Loss on sale of discontinued operations — 331.2 43.8
Loss (Income) from discontinued operations (6.1) 0.5 (18.2)
Amortization of Discount/Premium on Debt 21.6 18.9 21.0
Other Adjustments (2.3) (2.5) (1.4)
Changes in assets and liabilities:
Restricted cash (33.5) 1.4 14.7
Accounts receivable and unbilled revenue (92.0) 67.3 43.6
Inventories (23.1) (166.9) 117.0
Accounts payable 153.3 (41.4) (50.6)
Customer deposits 6.7 15.2 55.2
Taxes accrued (57.8) (89.5) (8.1)
Interest accrued 1.7 5.9 8.6
(Under) Overrecovered gas and fuel costs (104.3) 18.9 (107.6)
Exchange gas receivable/payable 93.3 (196.0) 191.3
Other accruals 11.4 (55.5) (203.1)
Prepayments and other current assets 4.2 9.9 25.9
Regulatory assets/liabilities 18.6 3.3 (13.7)
Postretirement and postemployment beneﬁts 35.4 82.6 (19.2)
Deferred credits (14.3) (28.1) (11.8)
Deferred charges and other noncurrent assets (36.3) 14.2 243.5
Other noncurrent liabilities 2.6 (26.6) (38.1)
Net Cash Flows from Continuing Operations 1,020.6 614.4 1,171.0
Net Cash Flows (used for) or from Discontinued Operations 2.2 (141.5) (133.3)
Net Cash Flows from Operating Activities 1,022.8 472.9 1,037.7
Investing Activities
Capital expenditures (517.0) (574.6) (531.9)
Proceeds from disposition of assets 7.1 586.5 419.2
Other investing activities (9.2) (17.6) (2.2)
Net Cash Flows used for Investing Activities (519.1) (5.7) (114.9)
Financing Activities
Issuance of long-term debt 450.0 1,401.5 —
Retirement of long-term debt (486.6) (1,366.9) (462.8)
Change in short-term debt (377.9) (227.6) (941.2)
Retirement of preferred shares — (346.2) (46.7)
Issuance of common stock 160.8 354.7 734.9
Acquisition of treasury stock (4.1) (2.5) (6.9)
Dividends paid — common shares (243.1) (284.0) (241.5)
Net Cash Flows for Financing Activities (500.9) (471.0) (964.2)
Increase (decrease) in cash and cash equivalents 2.8 (3.8) (41.4)
Cash and cash equivalents at beginning of year 27.3 31.1 72.5
Cash and cash equivalents at end of period $ 30.1 $ 27.3 $ 31.1
Supplemental Disclosures of Cash Flow Information
Cash paid for interest $ 383.0 $ 442.3 $ 493.8
Interest capitalized 2.3 2.5 2.4
Cash paid for income taxes 184.6 256.8 118.8

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Statements of Consolidated Capitalization
As of December 31, (in millions, except shares outstanding and par value) 2004 2003 2002

Common shareholders’ equity $4,787.1 $ 4,415.9 $4,174.9
Preferred Stocks, which are redeemable solely at option of issuer:
Northern Indiana Public Service Company—
Cumulative preferred stock — $100 par value —
41⁄4% series — 209,035 shares outstanding 20.9 20.9 20.9
4 ⁄2% series — 79,996 shares outstanding
1
8.0 8.0 8.0
4.22% series — 106,198 shares outstanding 10.6 10.6 10.6
Premium on preferred stock and other 0.3 0.3 0.3
Cumulative preferred stock — no par value —
Adjustable rate series A (stated value —
$50 per share), 473,285 shares outstanding 23.6 23.6 23.6
Series without mandatory redemption provisions 81.1 81.1 81.1
Redeemable Preferred Stocks, subject to mandatory
redemption requirements or whose redemption is
outside the control of issuer:
Northern Indiana Public Service Company—
Cumulative preferred stock — $100 par value —
73⁄4% series — 0; 0; and 11,136 shares
outstanding, respectively — — 1.1
8.35% series — 0; 0; and 27,000 shares
outstanding, respectively — — 2.7
Series with mandatory redemption provisions — — 3.8
Company-obligated mandatorily redeemable
preferred securities of subsidiary trust
holding solely Company debentures — — 345.0
Long-term debt 4,835.9 5,993.4 4,849.5
Total Capitalization $9,704.1 $10,490.4 $9,454.3

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Statements of Consolidated Long-Term Debt
NiSource Inc.:
Senior Debentures — 3.628%, due November 1, 2006 $ 144.4 — —
Debentures due November 1, 2006, with interest imputed at 7.77% (SAILSSM) — $ 135.8 $ 126.0
Unamortized discount on long-term debt 0.4 — —
Total long-term debt of NiSource, Inc. $ 144.8 $ 135.8 $ 126.0
Bay State Gas Company:
Medium-Term Notes —
Interest rates between 6.26% and 9.20% with a weighted average interest rate of 6.81%
and maturities between June 6, 2011 and February 15, 2028 48.5 68.5 80.5
Northern Utilities:
Medium-Term Note — Interest rate of 6.93% and maturity of September 1, 2010 4.2 5.0 5.8
Total long-term debt of Bay State Gas Company 52.7 73.5 86.3
Columbia Energy Group:
Debentures —
6.80% Series C — due November 28, 2005 — 281.5 281.5
7.05% Series D — due November 28, 2007 281.5 281.5 281.5
7.32% Series E — due November 28, 2010 281.5 281.5 281.5
7.42% Series F — due November 28, 2015 281.5 281.5 281.5
7.62% Series G — due November 28, 2025 229.2 229.2 229.2
Fair value adjustment of debentures for interest rate swap agreements — 11.2 30.6
Unamortized discount on long-term debt (96.0) (98.2) (108.0)
Subsidiary debt — Capital lease obligations 2.2 1.7 2.0
Total long-term debt of Columbia Energy Group 979.9 1,269.9 1,279.8
PEI Holdings, Inc.:
Long-Term Notes —
Whiting Clean Energy, Inc.— Interest rates between 6.73% and 8.58% with a weighted average
interest rate of 8.30% and maturity of June 20, 2011 298.6 301.5 302.5
Total long-term debt of PEI Holdings, Inc. 298.6 301.5 302.5
NiSource Capital Markets, Inc.:
Senior Unsecured Notes — 4.25%, due February 19, 2005 — 0.3 —
Subordinated Debentures — Series A, 73⁄4%, due March 31, 2026 — — 75.0
Senior Notes — 6.78%, due December 1, 2027 75.0 75.0 75.0
Medium-term notes —
Issued at interest rates between 7.38% and 7.99%, with a weighted average interest rate of
7.77% and various maturities between April 17, 2006 and May 5, 2027 190.0 220.0 300.0
Total long-term debt of NiSource Capital Markets, Inc. 265.0 295.3 450.0
NiSource Development Company, Inc.:
NDC Douglas Properties, Inc. — Notes Payable —
Interest rate between 3.8% and 12.6% with a weighted average
interest rate of 7.4% 36.7 2.6 5.1
Total long-term debt of NiSource Development Company, Inc. 36.7 2.6 5.1
NiSource Finance Corp.:
Long-Term Notes —
Floating Rate Notes — 1.93% at December 31, 2003, due May 4, 2005 — 250.0 —
75⁄8% — due November 15, 2005 — 900.0 900.0
3.20% — due November 1, 2006 250.0 250.0 —
77⁄8% — due November 15, 2010 1,000.0 1,000.0 1,000.0
Senior Unsecured Notes — 6.15%, due March 1, 2013 345.0 345.0 —
5.40% — due July 15, 2014 500.0 500.0 —
Floating Rate Notes — 2.92% at December 31, 2004, due November 23, 2009 450.0 — —
Fair value adjustment of notes for interest rate swap agreements 29.9 3.3 —
Unamortized discount on long-term debt (14.6) (15.5) (13.6)
Total long-term debt of NiSource Finance Corp., Inc. 2,560.3 3,232.8 1,886.4
Northern Indiana Public Service Company:
First mortgage bonds — Series NN, 7.10% — due July 1, 2017 — — 55.0
Pollution control bonds —
Issued at interest rates between 1.65% and 1.80%, with a weighted average interest rate of 1.75%
and various maturities between November 1, 2007 and April 1, 2019 278.0 278.0 223.0
Medium-term notes —
Issued at interest rates between 6.69% and 7.69%, with a weighted average interest rate of
7.30% and various maturities between July 8, 2007 and August 4, 2027 221.2 405.5 437.5
Unamortized premiums and discount on long-term debt, net (1.3) (1.5) (2.1)
Total long-term debt of Northern Indiana Public Service Company 497.9 682.0 713.4
Total long-term debt, excluding amount due within one year $4,835.9 $5,993.4 $4,849.5

page 10

Income Taxes

Income Taxes
Current
Federal $117.0 $132.0 $126.4
State 26.4 24.3 (3.3)
Total Current 143.4 156.3 123.1
Deferred
Federal 102.4 82.4 74.8
State 4.0 4.4 29.9
Total Deferred 106.4 86.8 104.7
Deferred Investment Credits (8.9) (8.9) (8.9)
Income Taxes Included in Continuing Operations $240.9 $234.2 $218.9

Total income taxes from continuing operations were different from the amount that would be computed by
applying the statutory Federal income tax rate to book income before income tax. The major reasons for this
difference were as follows:
Book income from Continuing
Operations before income taxes $671.1 $659.9 $617.0
Tax expense at statutory Federal income tax rate 234.9 35.0% 231.0 35.0% 216.0 35.0%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income
tax benefit 19.8 3.0 18.6 2.8 17.1 2.8
Regulatory treatment of depreciation differences 4.5 0.7 1.2 0.2 (2.2) (0.4)
Amortization of deferred investment tax credits (8.9) (1.3) (8.9) (1.3) (8.9) (1.4)
Low-income housing (3.9) (0.6) (5.1) (0.8) (5.1) (0.8)
Other, net (5.5) (0.9) (2.6) (0.4) 2.0 0.3
Income Taxes from Continuing Operations $240.9 35.9% $234.2 35.5% $218.9 35.5%

Deferred income taxes resulted from temporary differences between the financial statement carrying amounts
and the tax basis of existing assets and liabilities. The principal components of NiSource’s net deferred tax liability
were as follows:
At December 31, (in millions) 2004 2003 2002
Deferred tax liabilities
Accelerated depreciation and other property differences $1,680.3 $1,596.5 $1,482.0
Unrecovered gas and fuel costs 112.6 68.0 46.7
Other regulatory assets 303.9 279.0 238.4
SFAS No. 133 and price risk adjustments 40.9 49.0 42.7
Premiums and discounts associated with long-term debt 54.1 56.6 60.7
Total Deferred Tax Liabilities 2,191.8 2,049.1 1,870.5
Deferred tax assets
Deferred investment tax credits and other regulatory liabilities (177.9) (156.5) (62.4)
Pension and other postretirement/postemployment benefits (192.4) (190.9) (163.4)
Environmental liabilities (21.4) (20.1) (41.2)
Other accrued liabilities (43.9) (30.0) (52.3)
Other, net (19.2) (5.4) (38.2)
Total Deferred Tax Assets (454.8) (402.9) (357.5)
Less: Deferred income taxes related to current assets and liabilities 71.1 57.0 (4.8)
Non-Current Deferred Tax Liability 1,665.9 $1,589.2 $1,517.8

page 11

Statements of Consolidated Common
Stockholders’ Equity and Comprehensive Income
Accumulated
Additional Deferred Other
Common Treasury Paid-In Retained Stock Comprehensive Comprehensive
(in millions) Stock Stock Capital Earnings Compensation Income/(Loss) Total Income
Balance January 1, 2002 $2.1 $ 0.0 $2,637.3 $ 798.6 $(19.8) $ 51.2 $3,469.4
Comprehensive Income:
Net Income 372.5 372.5 $372.5
Other comprehensive income, net of tax:
Gain/loss on available for sale securities:
Unrealized (6.0) (6.0) (6.0)
Realized 0.3 0.3 0.3
Net unrealized gains on derivatives qualifying
as cash ﬂow hedges 17.7 17.7 17.7
Minimum pension liability adjustment (203.7) (203.7) (203.7)
Total comprehensive income $180.8
Dividends:
Common stock (240.8) (240.8)
Treasury stock acquired (6.9) (6.9)
Issued:
Common stock issuance 0.4 734.3 734.7
Employee stock purchase plan 0.9 0.9
Long-term incentive plan 17.0 (0.7) 16.3
Amortization of unearned compensation 19.9 19.9
Other 0.6 0.6
Balance December 31, 2002 $2.5 $ (6.9) $3,389.5 $ 930.9 $ (0.6) $(140.5) $4,174.9
Net Income 85.2 85.2 $ 85.2
Unrealized 1.4 1.4 1.4
Gain/loss on foreign currency translation:
Minimum pension liability adjustment 53.5 53.5 53.5
Dividends:
Common stock (284.8) (284.8)
Issued:
Balance December 31, 2003 $2.6 $ (9.4) $3,756.6 $ 731.3 $ (4.2) $ (61.0) $4,415.9
Net Income 436.3 436.3 $436.3
Gain/loss on foreign currency translation:
Minimum pension liability adjustment 5.2 5.2 5.2
Dividends:
Common stock (242.3) (242.3)
Issued:
Tax beneﬁts of options, PIES and other 5.2 0.1 5.3
Balance December 31, 2004 $2.7 $(13.5) $3,929.8 $ 925.4 $ (5.9) $ (51.4) $4,787.1

page 12

Statements of Consolidated Common
Stockholders’ Equity and Comprehensive Income
Common Treasury
Shares (in thousands) Shares Shares
Balance January 1, 2002 207,492 —
Treasury stock acquired (350)
Issued:
Stock issuance 41,400 —
Employee stock purchase plan 43 —
Long-term incentive plan 275 —
Balance December 31, 2002 249,210 (350)
Issued:
Long-term incentive plan 754 —
Issued:
Long-term incentive plan 1,337 —

page 13

Current Security and Bond Ratings
Columbia Energy Group
Description Moody’s S&P Fitch

Senior Unsecured Baa2 BBB BBB+

Northern Indiana Public Service Company

Senior Unsecured Baa2 BBB BBB+
Preferred Stock Baa3 BB+ BBB

NiSource Inc.

Senior Unsecured Baa3 BBB BBB
Commercial Paper Prime-3 A-2 F-2

page 14

Common Stockholders —State
Geographical Breakdown of Shareholders by State:
Percent Percent Percent Percent
State Holders of Total *Shares of Total State Holders of Total Shares of Total
Alabama 206 0.41% 71,316 0.03% New Hampshire 274 0.55% 120,403 0.04%
Alaska 29 0.06% 6,857 0.00% New Jersey 1,850 3.69% 8,476,840 3.12%
Arizona 545 1.09% 249,951 0.09% New Mexico 116 0.23% 36,751 0.01%
Arkansas 142 0.28% 44,855 0.02% New York 3,545 7.07% 240,715,107 88.73%
California 2,327 4.64% 933,123 0.34% North Carolina 572 1.14% 163,711 0.06%
Colorado 428 0.85% 269,502 0.10% North Dakota 44 0.09% 19,164 0.01%
Connecticut 936 1.87% 347,445 0.13% Ohio 3,631 7.24% 1,043,945 0.38%
Delaware 165 0.33% 44,445 0.02% Oklahoma 158 0.31% 43,953 0.02%
Dist. of Columbia 116 0.23% 67,644 0.02% Oregon 205 0.41% 61,628 0.02%
Florida 2,535 5.05% 999,236 0.37% Pennsylvania 2,350 4.69% 706,781 0.26%
Georgia 477 0.95% 210,540 0.08% Rhode Island 147 0.29% 59,008 0.02%
Hawaii 87 0.17% 25,332 0.01% South Carolina 268 0.53% 75,022 0.03%
Idaho 57 0.11% 29,844 0.01% South Dakota 64 0.13% 27,498 0.01%
Illinois 3,654 7.28% 1,947,161 0.72% Tennessee 330 0.66% 114,457 0.04%
Indiana 11,010 21.95% 8,631,562 3.18% Texas 1,313 2.62% 399,498 0.15%
Iowa 283 0.56% 132,820 0.05% Utah 88 0.18% 18,651 0.01%
Kansas 185 0.37% 54,237 0.02% Vermont 95 0.19% 31,205 0.01%
Kentucky 691 1.38% 223,410 0.08% Virginia 1,466 2.92% 483,641 0.18%
Louisiana 349 0.70% 68,271 0.03% Washington 377 0.75% 140,623 0.05%
Maine 271 0.54% 78,898 0.03% West Virginia 1,087 2.17% 240,497 0.09%
Maryland 1,051 2.10% 301,972 0.11% Wisconsin 1,058 2.11% 470,596 0.17%
Massachusetts 2,170 4.33% 1,428,567 0.53% Wyoming 41 0.08% 9,773 0.00%
Michigan 1,673 3.34% 927,466 0.34% Canada 56 0.11% 14,304 0.01%
Minnesota 530 1.06% 227,094 0.08% Other Foreign 131 0.26% 27,025 0.01%
Mississippi 119 0.24% 30,272 0.01% Totals 50,160 100.00% 271,293,852 100.00%
Missouri 498 0.99% 256,543 0.09%
Less Treasury Shares 668,482
Montana 77 0.15% 23,592 0.01%
Nebraska 119 0.24% 63,143 0.02% Total Shares Outstanding 270,625,370
Nevada 164 0.33% 98,673 0.04%

Common Stockholders
December 31, 2004 Number Percent Number Percent
Holder Category of Holders of Holders of Shares of Shares
Joint Tenants—Survivorship Rights 12,013 23.95% 6,270,180 2.31%
Individual—Female 13,879 27.67% 4,364,831 1.61%
Individual—Male 15,881 31.66% 7,375,144 2.72%
Corporations 881 1.76% 9,300,874 3.43%
Depositories 4 0.01% 239,810,064 88.39%
Nominee 11 0.02% 7,957 0.00%
Trusts 7,319 14.59% 4,050,757 1.49%
Miscellaneous 172 0.34% 114,045 0.04%
Total 50,160 100.00% 271,293,852 100.00%
Total Shares Outstanding 270,625,370
Share Size %
3,331 to 33.9 Shares 15,849 31.60% 170,805 0.06%
3, 34 to 49.9 Shares 2,291 4.57% 92,771 0.03%
3, 50 to 99.9 Shares 4,422 8.82% 317,842 0.12%
3,100 to 300.9 Shares 12,112 24.15% 2,233,678 0.82%
3,301 to 500.9 Shares 5,079 10.13% 2,004,815 0.74%
3,501 to 1,000.9 Shares 5,317 10.60% 3,834,994 1.41%
1,001 and over 5,090 10.15% 262,638,947 96.81
Total 50,160 100.00% 271,293,852 100.00%
Total Shares Outstanding 270,625,370

page 15

Gas Distribution Statistics
Year Ended December 31, (in millions) 2004 2003 2002 2001 2000

Net Revenues
Sales Revenues $3,859.6 $3,659.9 $2,905.4 $3,890.5 $1,980.5
Less: Cost of gas sold 2,850.8 2,625.3 1,921.6 2,887.9 1,415.9
Net Sales Revenues 1,008.8 1,034.6 983.8 1,002.6 564.6
Transporation Revenues 431.8 442.0 405.0 389.8 171.4
Net Revenues 1,440.6 1,476.6 1,388.8 1,392.4 736.0
Operating Expenses
Operation and maintenance 640.4 615.4 589.6 638.1 280.2
Depreciation and amortization 194.6 190.2 189.2 228.8 146.7
Other taxes 165.3 164.6 150.9 144.7 68.1
Total Operating Expenses 1,000.3 970.2 929.7 1,011.6 495.0
Operating Income $ 440.3 $ 506.4 $ 459.1 $ 380.8 $ 241.0

Revenues ($ in Millions)
Residential 2,388.5 2,356.2 1,790.7 2,231.0 1,250.4
Commercial 839.0 841.3 604.9 842.4 446.5
Industrial 197.4 194.0 101.9 131.8 92.2
Transportation 431.8 442.0 405.0 389.8 171.4
Off System Sales 214.2 86.1 191.5 636.8 97.2
Other 220.5 182.3 216.4 47.9 94.2
Total $4,291.4 $4,101.9 $3,310.4 $4,279.7 $2,151.9

Sales and Transportation (MMDth)
Residential sales 218.9 230.4 223.4 220.3 142.4
Commercial sales 85.3 89.7 83.6 92.8 57.3
Industrial sales 24.3 21.8 17.3 15.3 15.2
Transportation 534.5 522.9 536.9 507.7 304.6
Off System Sales 34.9 10.5 62.8 170.4 25.0
Other 0.6 0.9 0.2 0.3 (5.1)
Total 898.5 876.2 924.2 1,006.8 539.4

Heating Degree Days 4,887 5,134 4,757 4,500 4,965
Normal Heating Degree Days 4,967 4,949 5,129 5,144 5,173
% Colder (Warmer) than Normal (2)% 4% (7)% (13)% (4)%

page 16

Gas Distributi on Cu s tomers and Throughput Stati s tics by State
Customers (as of
December 31) 2004 2003 2002 2001 2000

Residential 2,389,032 2,278,768 2,318,862 2,294,395 2,352,219
Commercial 215,633 210,967 216,024 213,052 216,346
Industrial 5,806 6,009 5,818 5,835 5,952
Transportation 722,379 779,802 705,430 720,993 637,075
Other 61 135 146 150 24
Total Customers 3,332,911 3,275,681 3,246,280 3,234,425 3,211,616

Transportation 2004 2003
Customers by State RResidential Commercial Industrial & Other Total Total % Chg

Indiana 672,206 52,517 3,259 55,999 783,981 776,158 1.0%
Ohio 824,582 61,529 1,371 527,264 1,414,746 1,386,744 2.0%
Kentucky 91,028 9,870 106 40,957 141,961 141,205 0.5%
Pennsylvania 289,905 32,419 340 83,713 406,377 401,218 1.3%
Maryland 27,397 3,682 23 1,289 32,391 31,788 1.9%
Virginia 190,567 18,589 283 9,364 218,803 209,150 4.6%
New Hampshire 20,533 5,924 33 211 26,701 25,954 2.9%
Maine 17,637 6,817 18 453 24,925 24,480 1.8%
Massachusetts 255,177 24,286 373 3,190 283,026 278,984 1.4%
Total NiSource 2,389,032 215,633 5,806 722,440 3,332,911 3,275,681 1.7%

Throughput by State (MMDth) Residential Commercial Industrial Transportation Off-syst Sales Other Total

Indiana 63.7 25.2 16.3 171.7 0.1 0.4 277.4
Ohio 74.4 19.4 0.8 206.8 27.1 0.1 328.6
Kentucky 6.9 3.3 0.2 26.6 0.8 — 37.8
Pennsylvania 27.8 12.7 0.3 45.5 6.5 0.1 92.9
Maryland 2.5 1.6 — 2.8 0.2 — 7.1
Virginia 14.6 9.6 2.6 50.8 0.2 — 77.8
New Hampshire 1.8 2.4 0.5 2.4 — — 7.1
Maine 1.1 2.5 0.2 3.4 — — 7.2
Massachusetts 26.1 8.6 3.4 24.5 — — 62.6
Total NiSource 218.9 85.3 24.3 534.5 34.9 0.6 898.5

page 17

Gas Transmission and Storage Operations

Operating Revenues
Transportation revenues $ 668.0 $ 663.2 $ 730.4 $ 756.7 $ 199.9
Storage revenues 178.2 177.9 178.9 178.9 29.9
Other revenues 9.0 12.2 12.9 28.1 1.8
Total Operating Revenues 855.2 853.3 922.2 963.7 231.6
Less: Cost of gas sold 22.6 16.0 47.8 80.1 62.5
Net Revenues 832.6 837.3 874.4 883.6 169.1

Operating Expenses
Loss (Gain) on sale or impairment of assets 1.2 (1.8) (2.2) — 16.9
Other taxes 52.3 50.6 52.7 52.2 10.0
Total Operating Expenses 469.5 438.5 476.1 534.6 123.4

Throughput (MMDth)
Columbia Transmission
Market Area 978.3 1,018.9 1,043.8 970.2 285.0

Columbia Gulf
Mainline 539.1 612.6 614.4 626.3 114.2
Short-haul 102.5 124.4 146.9 184.7 28.8
Columbia Pipeline Deep Water 16.7 7.4 0.7 2.9 0.1
Crossroads Gas Pipeline 40.5 34.3 29.2 37.4 40.7
Granite State Pipeline 32.7 33.4 33.2 29.1 36.4
Intrasegment eliminations (537.1) (592.1) (553.9) (609.3) (109.8)
Total 1,172.7 1,238.9 1,314.3 1,241.3 395.4

page 18

Electric Operations

Net Revenues
Sales revenues $1,111.2 $1,092.8 $1,137.4 $1,064.5 $1,072.7
Less: Cost of sales 351.0 364.2 369.0 277.6 274.6
Net Revenues 760.2 728.6 768.4 786.9 798.1
Operating Expenses
Gain on sale of assets (1.6) — — — —
Other taxes 34.2 61.3 51.1 56.1 48.0
Total Operating Expenses 454.0 461.1 446.1 446.2 445.1

Revenues ($ in millions)
Residential $ 295.1 $ 294.9 $ 309.5 $ 295.7 $ 291.1
Commercial 294.1 289.8 297.2 292.9 282.2
Industrial 414.1 380.2 393.6 404.0 413.8
Wholesale 47.0 92.8 92.9 29.6 51.1
Other 60.9 35.1 44.2 42.3 34.5
Total $1,111.2 $1,092.8 $1,137.4 $1,064.5 $1,072.7
Sales (Gigawatt Hours)
Residential 3,104.3 3,122.5 3,228.4 2,956.9 2,953.3
Commercial 3,635.0 3,579.7 3,618.3 3,446.3 3,375.9
Industrial 9,309.4 8,972.2 8,822.4 8,935.5 9,494.9
Wholesale 1,176.2 2,623.2 2,983.5 845.0 1,546.9
Other 142.6 141.6 123.3 127.6 121.9
Total 17,367.5 18,439.2 18,775.9 16,311.3 17,492.9
Cooling Degree Days 582 572 1,015 801 693
Normal Cooling Degree Days 803 808 792 792 792
% Warmer (Colder) than Normal (28)% (29)% 28% 1% (13)%
Revenue per KWH (cents):
Residential 9.51 9.44 9.59 10.00 9.86
Commercial 8.09 8.10 8.21 8.50 8.36
Industrial 4.45 4.24 4.46 4.52 4.36
Residential Customers
Average annual KWH use per customer 7,912 8,045 8,388 7,752 7,774
Average annual electric bill $ 752.15 $ 759.81 $ 804.12 $ 775.22 $ 766.24
Electric Customers
Residential 392,342 388,123 384,891 381,440 379,908
Commercial 50,332 49,252 48,286 47,286 46,638
Industrial 2,528 2,543 2,577 2,643 2,663
Wholesale 22 21 22 23 37
Other 770 794 799 801 806
Total 445,994 440,733 436,575 432,193 430,052

On June 20, 2002 a settlement agreement was ﬁled with IURC regarding the electric rate review. The settlement agreement provides electric customers will receive a credit of $55M
each year for 49 months, beginning July 1, 2002.

page 19

Electric Generation and Production Statistics
Year in Net KW
Unit Service Capability 2004 2003 2002 2001 2000
(Kilowatt-hours in Thousands)
Megawatt-hours Generated by
Conventional Coal Fired
Steam Turbine—Michigan City
Generating Station:
Units 2 and 3(a) 1951 120,000 (1,674) (1,725) (2,002) (1,210) 7,761
Unit 12 1974 469,000 2,705,973 2,405,676 2,486,543 2,413,036 2,738,298
Station total 589,000 2,704,299 2,403,951 2,484,541 2,411,826 2,746,059

Dean H. Mitchell Generating Station:(b)
Unit 4 1956 125,000 0 0 (674) 374,324 230,560
Unit 5 1959 125,000 0 0 (388) 321,140 513,071
Unit 6 1959 125,000 0 0 (735) 555,396 564,095
Unit 11 1970 110,000 0 0 32,114 520,028 567,465
Station total 485,000 0 0 30,317 1,770,888 1,875,191

Bailly Generating Station:
Unit 7 1962 160,000 992,795 1,013,047 911,943 950,482 958,691
Unit 8 1968 320,000 2,105,916 1,289,827 1,918,972 1,706,284 1,862,584
Station total 480,000 3,098,711 2,302,874 2,830,915 2,656,766 2,821,275

R. M. Schahfer Generating Station:
Unit 14 1976 431,000 2,216,069 2,657,685 1,619,597 2,049,614 2,350,089
Unit 15 1979 472,000 2,942,038 3,001,038 2,602,456 3,017,124 2,873,483
Unit 17 1983 361,000 2,196,962 2,107,624 2,138,528 1,671,071 2,165,151
Unit 18 1986 361,000 1,990,524 2,238,720 2,388,925 2,171,866 2,356,513
Station total 1,625,000 9,345,593 10,005,067 8,749,506 8,909,675 9,745,236
Total conventional
steam generating stations 3,179,000 15,148,603 14,711,892 14,095,279 15,749,155 17,187,761

Megawatt-hours Generated by
Gas Turbine—Dean H. Mitchell
Generating Station:
Unit 9A 1966 17,400 0 0 0 969 805

Bailly Generating Station:
Unit 10 1968 30,900 314 806 336 1,071 955

R. M. Schahfer Generating Station:
Units 16A and 16B 1979 155,000 5,323 5,064 6,924 12,339 18,292
Total gas turbine
generating stations 203,300 5,637 5,870 7,260 14,379 20,052

Megawatt-hours Generated
by Hydroelectric—
Oakdale 1925 6,000 33,242 32,253 22,827 40,280 24,932
Norway 1923 4,000 28,629 22,355 24,855 30,196 17,208
Total hydroelectric 10,000 61,871 54,608 47,682 70,476 42,140
Total all generating stations 3,392,300 15,216,111 14,772,370 14,150,221 15,834,010 17,249,953

(a) Units 2 and 3 are ﬁred on gas only.

(b) D. H. Mitchell Generating Station taken out of service January 2002.

page 20

Fuel for Electric Generation
Coal Consumed by Generating Station for Electric Production (tons)
2004 2003 2002 2001 2000

Michigan City 1,538,985 1,351,752 1,389,568 1,331,813 1,525,548
Dean H. Mitchell(1) 0 0 22,560 1,094,636 1,123,902
Bailly 1,424,345 1,084,259 1,358,927 1,290,955 1,342,092
R. M. Schahfer 5,126,539 5,465,003 4,703,826 5,037,711 5,230,952
Total 8,089,869 7,901,014 7,474,881 8,755,115 9,222,494

Average Cost Per Ton of Coal Consumed(2) by Generating Station
2004 2003 2002 2001 2000

Michigan City $23.60 $26.71 $26.97 $24.23 $25.15
Dean H. Mitchell(1) N/A.0 N/A.00 N/A0 $23.92 $21.94
Bailly $32.86 $30.38 $30.00 $32.74 $28.73
R. M. Schahfer $27.21 $27.13 $27.79 $25.49 $24.70
Average of all stations $27.52 $27.50 $27.93 $26.17 $25.02

Mills Per Net KWH Generated for all Fuels, Total M Therms Burned all Fuels, and Btu Per Net KWH
Generated
2004 2003 2002 2001 2000

Mills/net KWH generated 14.83 15.25 14.96 15.01 14.07
Total M therms 1,673,421 1,630,234 1,567,534 1,770,762 1,900,768
Btu/net KWH generated 11,083 11,091 11,039 11,440 11,138

Fuel Mix for Electric Generation Including Purchased Power
2004 2003 2002 2001 2000

Coal 83.9 76.9 72.4% 92.5% 93.9%
Oil 0.0 0.0 0.0 0.0 0.0
Gas 0.0 (3) 0.0(3) 0.0 0.3 0.7
Hydro 0.3 0.3 0.2 0.4 0.2
Purchased Power 15.8 22.8 27.4 6.8 5.2
100.0% 100.0% 100.0% 100.0% 100.0%

(1)D. H. Mitchell Generating Station taken out of service January 2002.

(2)Includes the delivered cost of coal, fuel stock expense, ash handling and sale of slag.

(3)Gas usage was only .02% of total and rounded to 0.0%.

page 21

Capacity and Operating Margins
Capacity and Operating Margins provide a method by which electrical resources are displayed to show the
future electrical demands and energy requirements of the Northern Indiana Public Service Company’s
customers. Analyses are conducted in order to determine the optimum outcome of various electric resource
plans, which are necessary for customer demand and electric system reliability.

2004 2003 2002 2001 2000

Resources Available (at time of peak)
Net demonstrated capacity of units (MW) 3,392 3,392 3,392 3,392 3,392
Purchased power (MW) 628 827 774 98 282
Total resources of system (MW) 4,020 4,219 4,166 3,490 3,674
Scheduled outage (MW)* (502) (502) (502) 0 0
Random unavailability (MW) (221) (207) (245) (258) (316)
Resources available to meet peak load (MW) 3,297 3,510 3,419 3,232 3,358
Total internal system peak demand (MW) 2,922 3,054 2,978 2,998 2,870

Capacity Margins
Capacity margin expresses the difference between total demonstrated resources and the internal system peak
demand, as a fraction of the total demonstrated resources. Capacity margin permits examination and
calculation of operating needs.

2004 2003 2002 2001 2000

Total resources of system (MW) 4,020 4,219 4,166 3,490 3,674
Capacity margin (MW) 1,098 1,165 1,188 492 804
Capacity margin (percent) 27.3% 27.6% 28.5% 14.1% 21.9%

Operating Margins
Operating margin is capacity margin less the demonstrated resources unavailable because of predictable
events such as scheduled outages and variable events such as random unavailability. Consideration of these
variables explicitly incorporates the dimension of generation reliability into both utility operational and capacity
planning needs. The total internal system peak demand is subtracted from the resources available to meet peak
demand. This difference, divided by the total demonstrated resources and expressed as a percentage, is the
operating margin.

2004 2003 2002 2001 2000

Resources available to meet peak load (MW) 3,297 3,510 3,419 3,232 3,358
Operating margin (MW) 375 234 488
456 441
Operating margin (percent) 9.3% 6.7% 13.3%
10.8% 10.6%
Annual Load Factor 66.0% 61.8% 66.3% 61.6% 66.2%

*D.H. Mitchell Generating Station taken out of service January 2002 and is on indeﬁnite shutdown.

page 22

nisource Statistical Summary Book 2004

nisource Statistical Summary Book 2004

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